brine compatibility with metal

8/14/2019 Brine Compatibility with metal

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F O R M A T E B R I N E S C O M P A T I B I L I T Y W I T H M E T A L S

Formate BrinesCompatibility with Metals

Authored by Siv Howard,Formate Brines Consultant

Reviewed by Derek Milliams,Advanced Corrosion Management Services

Frank Dean,Ion Science

Commissioned by Cabot Specialty Fluids

This document reports accurate and reliable information to the best of our knowledge.

Neither the author nor the reviewers assume any obligation or liability for the use of the information presented herein.

December 2006

Photo: Courtesy of Sandvik


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P A G E 2

Contents

Purpose and Scope 3

Acknowledgements 3

Summary 3

1 Introduction to Formate Brines 42 Introduction to Oilfield Corrosion 4

2.1 Types of Corrosion 4

2.2 Types of CRAs and how they are chosen 5

3 HPHT Field Experience 6

4 What Makes Formates less Corrosive than Other Brines? 7

5 The Carbonate/Bicarbonate pH Buffer in Formate Brines 7

5.1 How the Carbonate/Bicarbonate Buffer Works 7

5.2 Buffer Protection against CO2(H2S) influx 8

6 Corrosion in Formate Brines in the Absence of Corrosive Gases 10

7 Corrosion in Formate Brines Contaminated with CO2 12

7.1 CO2Corrosion 12

7.1.1 CO2Corrosion of C-Steel 13

7.1.2 CO2Corrosion of 13Cr Steel 14

7.1.3 CO2Corrosion of Higher Alloy Steels 16

7.1.4 CO2Corrosion Rates 16

7.2 Impact of CO2on SCC 19

7.2.1 Testing by Hydro Corporate Research Centre 19

7.2.2 Testing by Statoil at Centro Sviluppo Materiali 20

8 Corrosion in Formate Brines Contaminated withH2S 21

8.1 Impact ofH2Son General and Pitting Corrosion 21

8.2 Impact ofH2Son SCC and SSC 21

8.2.1 Sulfide Stress Cracking (SSC) of Carbon and Low Alloy steels 21

8.2.2 Cracking of CRAs in H2SContaining Environments 22

8.2.3 High-Temperature Testing by CAPCIS 22

8.2.4 High-Temperature Testing by Statoil at Centro Sviluppo Materiali 24 8.2.5 Low-Temperature Testing by CAPCIS 24

8.3 Use ofH2SScavengers in Formate Brines 25

9 Corrosion in Formate Brines Contaminated with O2 26

9.1 Impact of O2on SCC 26

9.1.1 Testing by Hydro Research 26

9.1.2 Testing by CAPCIS 27

9.1.3 Testing by Statoil at Centro Sviluppo Materiali 28

9.2 Use ofO2Scavengers in Formate Brines 28

10 Catalytic Decomposition of Formates a Laboratory Phenomenon 29

11 Hydrogen Embrittlement of Metallic Materials in Formate Brines 30

11.1 Hydrogen Embrittlement 30

11.2 Sources of Hydrogen 30

11.2.1 Hydrogen Charging from Galvanic Coupling 30

11.2.2 Hydrogen Charging from Formate Decomposition 30

11.3 Field Evidence Totals Elgin Wells G1 and G3 31

12 Avoid Pitfalls in the Laboratory! 32

13 Avoid Pitfalls in the Field! 33

13.1 Four Simple Rules for Avoiding Corrosion in Formate Brines 33

13.2 Examples of Incorrect Use 33

References 35


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P A G E 3

Purpose and Scope

Cabot Specialty Fluids (CSF) is in the process of writing a

formate technical manual. This manual will cover formate

brines and their application in well construction operations:

chemical and physical properties, compatibilities and

interactions, applications, and Health, Safety and

Environmental aspects. While preparing the manual, CSF

has received numerous enquiries for information about the

corrosion characteristics of formates. In response, CSF

decided to commission a seperate review on metal

compatibility of formate brines. The outcome of this review is

reported in this document. The report includes some basic

corrosion theory, a review of laboratory test results with

formate brines, best practice procedures for testing formates,

advice on the proper field use of formates, and some

examples of improper use of formates in the field.

Acknowledgements

Some of the experimental work described in this document

was undertaken for CSF by Hydro Research and CAPCIS

Ltd. Other sources of information have been SPE and NACE

papers, and personal communication from corrosion

researchers and consultants.

In addition to the two reviewers Frank Dean, Ion Science, and

Derek Milliams, Advanced Corrosion Management Services,

I want to thank the following people for their valuable

contributions and advice: Peter Rhodes (Consultant), Salah

Mahmoud of MTL Engineering, John Herce of MTL Engineering,

Neal Magri of Technip Offshore, Inc., and Mike Billingham of

CAPCIS.

In addition, I want to thank Cabot Specialty Fluids for

supporting the preparation of this review, and especially John

Downs for his valuable technical contributions and editing.

Summary

The corrosivity of formate brines used in drilling, completion,

workover, and packer fluids for HPHT wells has been

thoroughly investigated over the past few years. One of the

drivers for this activity has been a spate of costly well

integrity failures that have been reported after operators have

used the traditional high-density halide completion brines.

Laboratory and field experience has shown that buffered

formate brines are considerably less corrosive than other

brines at high temperatures, even after exposure to large

influxes of acid gas.

Over the past 10 years, formate brines have been used in

more than 130 HPHT well construction operations where

they have been exposed to temperatures of up to 216C /

420F and pressures of up to 117.2 MPa / 17,000 psi.

There is no record of any corrosion incidents being caused

by buffered and correctly formulated formate brines under

these demanding conditions.

The low corrosivity of the formate brines is attributed to the

benign properties of the brine itself. Formate brines have a

naturally alkaline pH and can be buffered with carbonate/

bicarbonate buffers to maintain a favorable pH even after

large influxes of acid gas. As a matter of fact, it has been

shown that the pH in buffered formate brine never drops

below about 66.5 when contacted by acid reservoir gases.

Formate brines contain very low levels of halide ions, and are

thereby free of the corrosion problems commonly associated

with halides such as pitting and stress corrosion cracking.

Even with a significant level of chloride contamination, formate

brines have been shown to outperform uncontaminated

bromide brines. And last but not least, the formate ion is an

anti-oxidant, which limits the need for adding oxygen

scavengers, and avoids the problems that can occur when

these scavengers become depleted.

With the growing awareness of the shortcomings of the

halide brines, it is expected that formate brines will have an

increasingly important role in future HPHT well construction

operations.


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P A G E 4

1 Introduction toFormate Brines

High-density formate brines have been available to the

industry for use in drilling, completion, workover, and packer

fluids since the mid 1990s. This family of non-corrosive,

high-density, monovalent brines offers clear advantages over

the traditional halide family of brines in that their use is not

just limited to completion and packer fluids, but includes

solids-free drilling fluids, which offer exceptionally good flow

characteristics over the whole density range.

The primary uses for formate brines over the past 10 years

have been in demanding applications where conventional

drilling and completion fluids have not been able to meet the

required performance specifications. The applications where

formate brines have been used include:

HPHT completions and workovers to provide

compatibility with completion materials and reservoir

HPHT drilling to avoid well control problems anddifferential sticking

Reservoir drilling and completion to improve production

Narrow bore and extended reach drilling to improve

circulation hydraulics

Shale drilling to minimize environmental impact

Cesium formate, the highest density brine in the formate

family, has proven to be an excellent replacement for the

traditional high-density zinc bromide brine, and is now the

high-density completion fluid of first choice in the North Sea.

To date, cesium formate has been used in more than 130

HPHT well operations, at temperatures as high as 216C /

420F, at pressures up to 117 MPa / 17,000 psi and in the

presence of corrosive gases such asCO2, H2S, and O2.

Indeed, field experience has shown that formate brines have

given operators the ability to drill and complete challenging

HPHT wells with a degree of success, economy, and security

that would have been difficult to achieve using conventional

fluids.

Field experience has also shown that buffered, uninhibited

formate brines exhibit low corrosivity towards all types of

steel tubulars used in well construction and production

operations, even when contaminated with corrosive gases

and chlorides. This compatibility with carbon and low alloy and

stainless steel goods has been an important consideration forthe oil companies who have chosen formate brines for use in

their HPHT well constructions.

2 Introduction toOilfield Corrosion

2.1 Types of Corrosion

The aqueous corrosion of metals involves two electro-chemical

reaction zones in close proximity: a cathodic reaction zone, in

which electrons are taken from the metal to reduce a reactant

(e.g. protons, water, or oxygen) in an electrolyte(often a

solution of salts) which is in contact with the metal, and an

anodicreaction zone, in which the metal is oxidized

(corroded), liberating electrons into the metal. Electrons move

through the metal from the anodic to cathodic zone

balancing the electro-chemical reactions. The effects of

corrosion most commonly encountered in the sub-surface

oilfield environment fall broadly into the following categories:

General corrosion:General corrosion is a relatively slow

process where the metal loss is relatively uniform over the

exposed surfaces and typically occurs over long time scales.

Carbon steel and low alloy steels are particularly susceptible

to general corrosion in acid environments.

Pitting corrosion:Pits are typically millimeter-sized zones of

anodic corrosion commonly associated with high chloride

concentrations in solution. Pitting commences with the

localized breakdown of a passivating scale on a metal. This

exposes small areas of oxidizable metal. Chloride preferentially

migrates to these local anodic zones, and assists in removal

of anodically oxidized metal, to form pits. The metal surface

outside the pits is cathodic and supports the reduction of, for

example, dissolved oxygen from the electrolyte. Pitting

corrosion is characterized by a high cathodic to anodic area

ratio. Metal dissolution is confined to pits that deepen much

faster than the rate of average wall loss associated with

general corrosion.

Stress Corrosion Cracking (SCC) is a destructive and fast-

acting effect of corrosion that can cause catastrophic failure

of Corrosion Resistant Alloy (CRA) oilfield tubulars and

equipment, sometimes within a matter of days. SCC cracks

develop from local defects in the surface oxide film, often

from sites of active pitting corrosion. For SCC to occur, tensile

stresses in the material are required in addition to the presence

of a corrosive environment and a susceptible material (Figure 1).

Increasing stress, temperature, and concentration of, for

example, halide ions, together with corrosive oilfield gases,

increase the risk of metal failure from SCC.

Figure 1Factors required for stress corrosion cracking (SCC).


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P A G E 5

Hydrogen damage is a term used to refer to a variety of

deleterious phenomena for example SSC, SOHIC, HIC, and

hydrogen embrittlement which affect metals when they

contain atomic (diffusible) hydrogen. The causes are broadly

two-fold. Either the hydrogen is dissolved into the metal at

high temperature (the higher the temperature, the less specific

the source of hydrogen has to be) then the metal is rapidly

cooled to a low temperature leading to hydrogen over-

saturation, or the hydrogen enters the steel directly at a low

temperature (less than about 100C / 212F) due to corrosion

involving hydrogen promoters, the most important oilfield

hydrogen promoter being hydrogen sulfide.

Sulfide Stress Cracking (SSC) occurs during corrosion of steel

under tensile stress in the presence of water and hydrogen

sulfide. It is generally accepted that SSC is in part caused by the

promotion of hydrogen entry into the steel by hydrogen sulfide.

This causes steel embrittlement which, under tensile stress,

causes the steel to crack. High strength carbon and low alloy

steels and hard weld zones are particularly prone to SSC.

Hydrogen Induced Cracking (HIC) occurs in carbon and

low alloy steels, when atomic hydrogen diffuses into the steel

and then combines to form molecular hydrogen, particularly

in the vicinity of steel inclusions, such as manganese sulfide.

The build up of hydrogen pressure at inclusions leads to the

formation of planar cracks. The linking of these cracks, internally

or to the surface of the steel, results in Step Wise Cracking

(SWC) that can destroy the integrity of the component. Near

the surface of the steel the cracks can lead to the formation of

blisters. HIC damage is more common in components made

from rolled plate than in those made from seamless material.

HIC generally occurs at temperatures below 100C / 212F

and in the presence of certain corrodants called hydrogen

promoters, such as hydrogen sulfide. No externally applied

stress is needed for the formation of HIC.

Stress oriented hydrogen induced cracks (SOHIC) is

related to SSC and HIC/SWC. In SOHIC, staggered small

cracks are formed approximately perpendicular to the

principal stress (residual or applied) resulting in a ladder-like

crack array linking (sometimes small) pre-existing HIC cracks.

The mode of cracking can be categorized as SSC caused by

a combination of external stress and the local straining

around hydrogen induced cracks.

Hydrogen Embrittlement (HE) of metals, particularly of high

alloy steels, is the physical result of high levels of hydrogen

uptake into the metal. Hydrogen is much more soluble

and diffusible in metals at high temperatures than at low

temperatures (defined as below 100C / 212F). Embrittlement,

therefore, normally occurs as a consequence of corrosion at

high temperature, followed by sufficiently rapid cooling of the

metal to entrap the hydrogen at low temperature. It may also

result from intense hydrogen entry due to corrosion at low

temperature in the presence of a hydrogen promoter.

2.2 Types of CRAs and how they are chosen

Well engineers select the metallurgy of their sub-surface tubulars

according to the composition of the produced fluids/gases and

the downhole temperature profile. If there is any risk of CO2

production during the lifetime of the well they will tend to select

Corrosion Resistant Alloy (CRA) steels that contain chromium,

nickel, and sometimes molybdenum. High downhole tempera-

tures and the presence of H2Sand Cl-necessitate the selection

of more expensive CRAs with high alloy metal content. Given

the high cost of the types of CRA tubulars being used in HPHT

wells and the cost of a well intervention and loss of productionif the material should fail, it is important to maximize their life

expectancy. The cost of a rig for an offshore HPHT well

intervention can run into several million dollars and the waiting

time for both the rig and new CRA material might be up to a

year. It is therefore particularly important that the integrity and

life expectancy of the tubulars is not compromised by adverse

interactions with completion, workover, and packer fluids.

Table 1 lists some CRAs commonly used in tubulars. The

recommended temperature ranges for the various CRAs vary

between the OTG producers, and no universally accepted

limits exist. The temperature limits shown in Table 1 are taken

from the Sumitomo selection guide [1] and apply when CO2is

present. The recommended applicability limits of the alloys in

Table 1 are also dependent upon chloride concentration and,

when present, upon the levels of H2S.

There are also quite a few austenitic alloysthat, because of their

corrosion resistance properties, are commonly used in well

applications. These alloys are characterized by their high content

of chromium and nickel. They are mainly used as material for

packers, safety valves, hangers, etc. In some cases they can be

sensitive to hydrogen embrittlement and other forms of attack

often associated with H2S. The industry standard for sour service

materials [2] provides more information on the sensitivity of

austenitic and other corrosion resistant alloys to this common

contaminant of oil and gas production environments.

Table 1 Martensitic and Duplex steels commonly used in oilfield tubulars. The application limits apply in the presence of CO2and are

further restricted by the level of CO2, H2S, and Cl-[1].

Group Name Cr % Ni % Mo %General application limit

[C] [F]

Martensitic

13Cr 13 -- --


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P A G E 6

3 HPHT Field Experience

Over the last 10 years formate brines have been used in more

than 130 HPHT applications at downhole temperatures as high

as 216C / 420F and at pressures up to 117 MPa / 17,000 psi.

Since their first use in HPHT wells, there have been no

corrosion incidents caused by formate brines when used

according to the guidelines described in this document.

Table 2 HPHT field experience with formate brines provided by CSF over the past seven years.

BP Rhum3/29a

ShellShearwater

MarathonBraemar

BPDevenick

TotalElgin/

Franklin

StatoilHuldra

No. of wells 3 6 1 1 10 6

HydrocarbonGas

condensateGas

condensateGas

condensateGas

condensateGas

condensateGas

condensate

Max. tempC 149 182 135 146 204 149

F 300 360 275 295 400 300

Completion material CRA S13Cr 25Cr 13Cr 13Cr 25Cr S13Cr

Liner material CRA S13Cr 25Cr 22Cr VM110 P110 S13Cr

Packer material CRA 718 718 718 718 718 718

Brine density g/cm3 2.00 2.20 2.05 2.20 1.80 1.85 1.60 1.65 2.10 2.20 1.85 1.95

Reservoir pressureMPa 84.8 105.6 74.4 72.4 115.3 67.5

psi 12,300 15,320 10,800 10,500 16,720 9,790

CO2 % 5 3 6.5 3.5 4 4

H2S ppm 5 10 20 2.5 5 20 50 10 14

Exposure time days 250 65 7 90 1.6 yrs 45

ApplicationPerforationCompletionWorkover

Well killCT

WorkoverPerforation

WorkoverPerforation

DrillCompletion

WorkoverCompletion

CTWell kill

Perforation

DrillingCompletion

Screens

StatoilKvitebjrn

StatoilKristin

BP

High IslandA-5

DevonWest

Cameron165 A-7, A-8

DevonWest

Cameron575 A-3

Walter O&G

Mobile Bay862

No. of wells 7 to date 7 to date 1 1 1 1

HydrocarbonGas

condensateGas

condensateGas

Gascondensate

Gas Gas

Max. tempC 155 171 163 149 135 216

F 311 340 325 300 275 420

Completion material CRA S13Cr S13Cr S13Cr 13Cr 13Cr G-3

Liner material CRA 13Cr S13Cr S13Cr 13Cr 13Cr G-3

Packer Material 718 718 718 718 718 718 G-3

Brine density g/cm3 2.00 2.06 2.09 2.13 2.11 1.03 1.142.11

1.49 packer

Reservoir pressureMPa 81 90 99 80 74 129

psi 11,700 13,000 14,359 11,650 10,731 18,767CO2 % 2 3 3.5 5 3 3 10

H2S ppm Max 10 12 17 12 5 5 100

Exposure time days 57 574

3 yrs packer2 and 1.3 yrs 1.4 yrs

201.5 yrs packer

Application

DrillingCompletion

ScreensLiners

DrillingCompletion

Screens

Well killCompletion

PackerPacker Packer

Well killCompletion

Packer


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P A G E 7

4 What Makes Formates lessCorrosive than Other Brines?

There are several features of formate brines that make them

inherently less corrosive than other brines used by the oil

industry.

Halide-fee

Conventional halide brines (NaCl, KCl, NaBr, CaCl2, CaBr2,

ZnBr2, and their blends), and particularly chlorides, are known

to promote several forms of corrosion. Localized corrosion,

such as pitting and SCC are promoted in halide environments,

and the severity increases with increased halide concentration.

Even after contamination with moderate levels of chloride

ions (Cl-), formate brines still retain their non-corrosive

characteristics in most applications.

Antioxidant

Oxidants, such as O2are known to cause corrosion

problems. The formate ion is a well-known antioxidant or free

radical scavenger, used in many industrial and medicalapplications.

Favorable alkaline pH

Formate salts dissolved in water exhibit a naturally favorable

pH (8-10).

In non-oxygenated solutions, corrosivity is determined in part

by pH. The lower the pH, the greater the tendency for

corrosion. In addition, pH determines the stability/solubility of

corrosion scales.

Traditional high-density halide brines typically have pH values

of between 2 and 6 (depending on the type of halide) and are

therefore naturally more corrosive than formate brines.

Compatibility with Carbonate-based pH buffer

The only truly reliable protection against corrosion from acid

gas (CO2and H2S) is to pre-treat the receiving brine with a

carbonate/bicarbonate buffer. The buffer not only helps to

maintain the brine pH in the safe alkaline zone but also

promotes metal passivation.

Traditional high density completion and packer fluids based

on divalent halide brines (CaCl2, CaBr2, ZnBr2) cannot be

buffered because even small amounts of added carbonate/

bicarbonate buffer are precipitated out. Carbonate/bicarbonate

buffers are soluble in formate brines, and can be formulatedto make fluids that remain pH stable in the face of quite large

influxes of CO2.

In order to fully understand how the buffer in the formate

brine enhances the corrosion protection provided by the

formate brine itself, one first needs to understand how this

buffer works and how it reacts to influxes of common acid

gases such as CO2and H2S.

5 The Carbonate/BicarbonatepH Buffer in Formate Brines

Formate brines provided for field applications should be

buffered by the addition of potassium or sodium carbonate

and potassium or sodium bicarbonate. Typical recommended

levels are 6 to 12 lb/bbl of potassium carbonate or a blend of

potassium carbonate and potassium bicarbonate. The main

purpose of this buffer is to provide an alkaline pH and to

prevent the pH from fluctuating as a consequence of acid or

base influxes into the brine. The buffer also plays a very

important part in encouraging the formation of the high quality

protective carbonate film on the steel surfaces.

5.1 How the Carbonate/Bicarbonate Buffer Works

A pH buffered solution is defined as a solution that resists a

change in its pH when hydrogen ions (H+) or hydroxide ions

(OH-) are added. The ability to resist changes in pH comes

about by the buffers ability to consume hydrogen ions (H+)

and/or hydroxide ions (OH-).

The carbonate/bicarbonate buffer system provides strong

buffering at two different pH levels:

Higher buffer level at pH = 10.2

(1)

where = 10.2

At pH = 10.2 ( ) the buffered solution contains the same

amount of carbonate ( ) and bicarbonate ( ).

Lower buffer level at pH = 6.35

(2)

where

= 6.35

At pH = 6.35 ( ) the buffered solution contains the

same amount of bicarbonate ( ) and carbonic

acid ( ).

The exact levels of and

will vary somewhat with

brine concentration, temperature, and pressure.

3


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P A G E 8

Figure 2 demonstrates how the carbonate buffer works when

a strong acid is added. The carbonate will react with added

acid until all the carbonate is consumed. As long as there is

still carbonate left in the solution, the pH will remain high,

around the higher buffer level = 10.21. As soon as the

carbonate is consumed, the pH will drop down to the lower

buffer level where it will remain as long as bicarbonate is

available to react with the added acid and be converted to

carbonic acid. In order for the pH to drop down below this

second buffer level, an acid would need to be added that is

stronger than the carbonic acid that is formed. As any CO2

gas influx into the buffered solution will dissolve and be

converted to carbonic acid, a CO2influx is therefore not

capable of pulling the pH much below this second buffer

level.

5.2 Buffer Protection against CO2(H2S) influx

The major cause of acidification of conventional completion

brines is influx of carbon dioxide gas (CO2) into the wellbore:

(3)

(4)

(5)

Depending on the pH in the brine system, the dissolved CO2

will remain in the brine as either carbonic acid (H2CO3) or

bicarbonate (HCO3-) according to the equation 5. This is

demonstrated in Figure 3. As more CO2gas enters into the

brine, the carbonic acid concentration builds up and the pH

drops and allows unbuffered brines to acidify.

The three different brine systems in Figure 3 will react in the

following way to a CO2influx:

Conventional divalent halide brinescannot be buffered

with carbonate/bicarbonate because the corresponding

metal carbonate (CaCO3, ZnCO3) will precipitate out of

solution resulting in the formation of solids in the clear

packer/completion fluid. These divalent brines have a

naturally low pH (26) and the influx of CO2will, dependent

on the partial pressure of CO2, further lower the pH. The

CO2will largely be converted to carbonic acid, which is

very corrosive.

Buffered formate brinesare capable of buffering large

amounts of CO2. Unless the influx is unusually large, the

brine will maintain a pH (at around the upper buffer level)

which is high enough to prevent carbonic acid being

present in the fluid. With a large influx of CO2, the pH will

drop down to the lower buffer level (pH = 6.35) where it will

stabilize. Measurements of pH in formate brines exposed

to various amounts of CO2have confirmed that the pH

never drops below 66.5. This pH is still close to neutral,

meaning that this brine system cannot be acidified toany great extent by exposure to CO2.

Unbuffered formate brines: The pH of these brine

systems behaves very much like halide brines when

exposed to CO2gas. However, they do have a higher initial

pH, and the pH drop will be limited as the formate brine is

a buffer in itself (pKa= 3.75). If there is any chance of an

acid gas influx, the use of unbuffered formate brines is not

recommended.

Figure 2The pH of water buffered with carbonate as a function of added strong acid (H+). The x-axis shows the fraction of the bufferthat is consumed by the added acid. As can be seen, carbonate will buffer twice, first at pH pKa2= 10.2 (upper buffer level) and then at

pH = pKa1= 6.35 (lower buffer level). If the added acid is carbonic acid (from CO2influx), the pH can never drop much below pKa1.


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P A G E 9

Influx of CO2into a wellbore is often accompanied by

hydrogen sulfide (H2S). H2Sis a very weak acid with a pKa1at

around 7. H2Scorrosion is generally suppressed in alkaline

scenarios by the formation of non-soluble sulfide films.

Therefore sustained corrosion by hydrogen sulfide in the

presence of buffered formate brines is unlikely to occur.

In order to get the full benefit of the carbonate/bicarbonate

buffer in the formate brine, both the buffer level and buffer

capacity need to be maintained during field use. Over-

treatment with potassium carbonate is most often not a

problem.

Figure 3 pH as function of CO2influx in a typical halide brine, an unbuffered formate brine, and a buffered formate brine.


10/36


P A G E 1 0

Table 3General corrosion rates of C-steel in formate brines.

FluidDensity pH

(diluted1:10)

Temp. days P-110 C-110 Q-125

s.g. ppg C F mm/y MPY mm/y MPY mm/y MPY

NaFo 1.26 10.5 10.0 163 325 7 0.008 0.3

CsFo 12.0 163 325 7 0.000 0.0

CsFo + 5%KCl 2.18 18.2 10.5 177 350 40 0.076 3.0 0.065 1.0 0.051 2.0

CsFo 12.0 177 350 7 0.003 0.1CsFo 10.0 191 375 ? 0.005 0.2

CsFo 10.0 204 400 17 0.008 0.3

CsFo 1.94 16.2 218 425 30 0.177 7.0

Table 4General corrosion rates of CRAs in formate brines.

FluidDensity pH

(diluted1:10)

Temp. days 13CrModified

13Cr22Cr 25Cr

s.g. ppg C F mm/y MPY mm/y MPY mm/y MPY mm/y MPY

KFo 1.26 10.5 9.8 66 150 30 0 0 0 0

KFo1.57 13.1 9.8 66 150 30 0 0 0 0

NaFo 1.26 10.5 10.0 163 325 7 0 0.0 0 0.0

CsKFo

+ 3 g/L Cl-1.95 16.2 10.4 165 329 30 0.01 0.39

KFo 1.26 10.5 9.8 185 365 30 0 0 0 0

KFo 1.57 13.1 9.8 185 365 30 0.043 1.7 0 0

CsFo 10.0 191 375 ? 0 0.0 0.03 1

CsFo 10.0 204 400 17 0.003 0.1 0.03 1

CsFo 204 400 7 0.076 3

CsFo 1.94 16.2 218 425 30 9.25 364 0.41 16

Shaded area = outside the operating envelope of the specific CRA

6 Corrosion in Formate Brines inthe Absence of Corrosive Gases

In the absence of corrosive gasses and within the operating

envelope of the specific metal (as defined in Table 1 and its

associated text), formate brines are essentially non-corrosive to

all forms of steels used in oil and gas well construction, even

when contaminated with chloride ions. Table 3 and Table 4 list

general corrosion rates for a variety of formate brines at

temperatures up to 218C / 425F, collected from various

published and unpublished sources [3].

The general corrosion rates of C-steel and CRAs in formate

brines are negligible regardless of the temperature. Localized

corrosion and SCC have never been observed. The use of

corrosion inhibitors in formate brines is neither necessary nor

recommended.


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P A G E 1 1

Corrosion comparison:

Cesium formate brine versus zinc bromide brine

Traditional high-density halide brines are known to cause or

facilitate pitting corrosion due to their low pH and high

content of halide ions (Cl-, Br-). A comparative corrosion test

[4] has been carried out at 204C / 400F with C-steel

exposed to a high density cesium formate brine and in a

blend of zinc bromide and calcium bromide brines, both with

a density of 2.18 s.g. / 18.2 ppg. The mixed bromide brine

was tested with and without a corrosion inhibitor. The testing

was carried out in 100 mL C-steel pressure vessels. The

corrosion of the walls of the vessels was determined by

measuring the weight loss of the vessels after 12 days of

exposure to the brines. The results are shown in Table 5. The

CaBr2/ZnBr2brine promoted severe localized corrosion at the

interface between the liquid and vapor. The presence of a

corrosion inhibitor marginally reduced the general corrosion

rate but seemed to amplify the localized corrosion. The

weight loss of C-steel in the bromide brine was found to be

about 100 times higher than in the uninhibited formate brine

and the depth of the localized metal corrosion in the bromidewas about 1,000 times higher than in formate. No significant

localized corrosion or pitting corrosion and only negligible

general corrosion was experienced in the formate brine.

Pressure build-up in the headspace of the test vessels was

monitored in these tests, and the bromide brine was shown

to create higher pressures at 204C / 400F than the formate

brine. The pressure build-up with the bromide brine, resulting

from the evolution of hydrogen gas, is thought to have been

caused by the corrosion reactions.

Table 5General and localized corrosion on C-steel (P-110)

exposed to inhibited and uninhibited calcium/zinc bromide and

cesium formate brines at 204C / 400F.

Test Fluid

Generalcorrosion

rate

Rate ofmaximum

penetration

mm/y MPY mm/y MPY

Uninhibited CaBr2/ZnBr2 0.84 33 7.72 304

Inhibited CaBr2/ZnBr2 0.66 26 13.1 517

Csformate 0.008 0.3


12/36


13/36


P A G E 1 3

formic acid, a stronger acid (one with a lower pKa) would

need to be introduced. An example of this would be

hydrochloric acid (HCl). The presence of a very small amount

of formic acid has actually proven to be a benefit in promoting

the formation of iron carbonate films that protect steel

surfaces against CO2 corrosion [7].

It is important to keep in mind that the main purpose of the

buffer provided in formate brines is to maintain a high pH so

that CO2corrosion is prevented. In a realistic field situation the

likelihood that a buffered formate brine would ever receive a

CO2gas influx large enough to overwhelm the buffer is low.

(Figure 3). Traditional high-density halide-based brines do not

have this advantage, and CO2corrosion will commence after

even a minor influx of CO2.

Even if a CO2influx is sufficient enough to overwhelm the

carbonate component of the powerful pH buffer,a protective

iron carbonate layer will form much faster and much more

efficientlyin a buffered formate than in other high density

completion brines. Here is why:

Both carbonic acid and formic acid are known to be corrosive

to C-steel and lower alloyed steels and to some CRAs, such

as 13Cr, at elevated temperatures. The corrosion takes place

according to the following mechanisms, respectively:

(12)

and to a lesser extent;

(13)

Ferrous iron liberated by these reactions builds up in solution

and eventually reaches a level at which the solubility of iron

carbonate is exceeded locally on the corroding surface.

Further corrosion will then cause the build-up of an iron

carbonate layer on the steel surface:

(14)

Alternatively or additionally to the formation of this iron

carbonate layer a magnetite (Fe3O4) layer can be formed.

Both the iron carbonate and the magnetite films are known to

be extremely efficient in inhibiting further corrosion.

Factors that will influence the quality of the film are [7]:

Volume to surface ratio. The ratio between the solution

volume and the area of steel exposed to the fluid. This is

not a variable in an annular well environment, and it is

therefore important to accurately reproduce this in a

laboratory test environment. 24 mL/cm2is an acceptable

range. Using higher ratios will generate misleading

corrosion predictions. As an example, increasing this ratio

by a factor of 10 (typical ratio used for corrosion testing =

20 mL/cm2), has been shown to double the measured

corrosion rate of 13Cr steel at 120C.

Amount of carbonate in the uid.The build-up of iron

carbonate depends on the solubility product of iron

carbonate. This means that as more carbonate ions are

present in the fluid, the less dissolved iron (corrosion

product) is needed to saturate the fluid close to the metal

surface and start film formation.

Rate of initial corrosion.A high rate of corrosion

immediately before the iron carbonate layer forms is

known to increase the quality of the layer.

Buffered formate brines that are exposed to a large amount

of CO2form a higher quality protective layer than other

acidified completion brines because they provide both a

higher amount of carbonate (see bullet point 2 above effect

of buffer) and a higher rate of initial corrosion (see bullet point

3 above the additional small amounts of formic acid seem

not only to slightly increase the initial high corrosion rate but

also to significantly further promote the formation of the iron

carbonate layer).

7.1.1 CO2Corrosion of C-SteelIf the carbonate component of the buffer in a formate brine is

overwhelmed by CO2influx, the pH will start decreasing and

CO2corrosion will take place according to Equations 12 and 13.

An initial period of high general corrosion will be experienced

prior to the build-up of the protective iron carbonate layer.

For C-steel this initial phase of high rates of general corrosion

is readily measured by short-term weight loss tests. There are

cases in the oilfield literature where exaggerated and

misleading CO2corrosion rates have been reported with

formates as a consequence of measuring the short-term

weight loss and then extrapolating this rate linearly over time

to create annual corrosion figures. It has therefore been

advised [6][7] not to use standard short-term weight loss

methods to predict long-term CO2corrosion rates for C-steel

in formate brines.

Compared with halide brines, formate brines have been

shown to be much less aggressive to C-steel, even in tests

where high CO2additions have decreased the pH to the

lower buffer level [8]. Figure 4 shows photos of 1.5 mm thick

C-steel coupons that have been exposed to 1.53 s.g. / 12.8

ppg calcium bromide and potassium formate brines acidified

with CO2at temperatures varying between 120C / 248F and

180C / 356F [7]. The coupon to the left shows severe

localized corrosion attacks on the coupon that was exposed

to the bromide brine, and the coupon to the right shows that

only general corrosion has taken place in the potassiumformate brine. A SEM photo of an iron carbonate layer

formed on C-steel in a formate brine is shown in Figure 5.

The film is very dense, of thickness 5 to 20 m. By comparison,

the surface layer that was formed in the calcium bromide

brine was found to be of a duplex structure with a thickness

of 100 to 200 m. Table 6 shows weight loss data and actual

local corrosion rates for the same coupons. Adding a

commonly used corrosion inhibitor to the bromide brine did

not improve the performance or stop the localized corrosion.

No additional chloride was added to the brines used in these

tests.


14/36


P A G E 1 4

Table 6 Average corrosion rate and rate of the deepest attack

for C-steel in 1.53 s.g. / 12.8 ppg bromide brine and buffered

KFo brine exposed to a large CO2influx. The experiments were

commenced at 120C / 248F, with an excursion to and from

180C / 356F [7].

Fluid

Corrosion rate

Average rate Deepest attack

mm/y MPY mm/y MPY

CaBr2 0.39 15.4 >8.71) >3421)

CaBr2inhibited

0.34 13.4 >8.71) >3421)

KFo 0.30 11.8 --- ---

1) Perforated, i.e. attack > coupon thickness = 1.5 mm

Real-time corrosion rates for C-steel in various formate and

bromide brines exposed to a large amount of CO2are shown

in the plot in Figure 6. This plot is based on Linear Polarization

Resistance (LPR) measurements that have been calibrated

against weight loss. As can be seen, a protective layer wasformed on the metal surfaces exposed to the formate brines

within the first 2030 hours of exposure to CO2. The scatter in

the bromide data during the initial period with high corrosion

rates indicates that localized corrosion was taking place.

7.1.2 CO2Corrosion of 13Cr Steel

13Cr steel has been shown to behave in a similar manner to

C-steel when exposed to formate brines that have received a

large influx of CO2. A protective layer is formed during a short

initial period of high general corrosion activity.

As with C-steel, formate brines in which the pH has been

substantially decreased to the lower buffer level by a large

influx of CO2appear to be much less aggressive towards

13Cr than acidified halide brines. Figure 7 (see left-hand

photo) shows severe localized corrosion of a 13Cr steel

coupon exposed to calcium bromide brine acidified with CO2

at temperatures varying from 120C / 248F to 180C / 356F.

A 13Cr coupon exposed to formate brine under the same

test conditions shows only general corrosion (see right-hand

photo in same figure). Weight loss corrosion rates for the

same coupons are shown in Table 7 along with the maximum

depths of pits caused by localized corrosion.

A SEM photo of the film formed in the formate brine is shown

in Figure 8. This film is thicker (100 m) than the one seen on

C-steel, and the film quality and ability to inhibit corrosion are

not quite as good.

Figure 4 C-steel test specimens after exposure to inhibited

calcium bromide and potassium formate (both 1.53 s.g. / 12.8

ppg) with a large CO2influx at 120C / 248F, with an excursion

to and from 180C / 356F [7]. Severe localized corrosion

attacks are seen in the calcium bromide brine. The potassium

formate brine only caused general corrosion. (The CO2influxwas large enough to overwhelm the upper buffer level and drop

the pH to the lower buffer level in the formate brines.)

Figure 5 SEM photo of iron carbonate protective layer formed

on C-steel in a potassium/cesium formate brine where pH was

pulled down to the lower buffer level by a large influx of CO2.

The thickness of the layer is about 5-20 m.

CaBr2 K formate

Corrosion

film

C-steel


15/36


P A G E 1 5

Figure 6 LPR plot showing initial corrosion of C-steel in potassium formate potassium/cesium formate and calcium bromide brines at

various temperatures. All brines were exposed to a large CO2influx. The time scale starts from the time of acidification with CO2. An initial

short period of high corrosion rates can be seen in the formate brines before the protective iron carbonate layers are formed. No distinct

peak can be seen in the bromide brines. The corrosion inhibitor in the bromide brine appears to have no impact on the CO2corrosion.

Figure 7 13Cr test specimens after exposure to inhibited

bromide (1.53 s.g. / 12.8 ppg) and potassium formate (1.53 s.g. /12.8 ppg) with a large influx of CO2where pH had been pulled

down to the lower buffer level. Severe localized corrosion

attacks are seen in the calcium bromide brine. The potassium

formate brine only caused general corrosion.


on 13Cr in potassium/cesium formate brine where pH waspulled down to the lower buffer level by a large influx of CO2.

The thickness is about 50100 m.

CaBr2 K formate

Corrosion

film

13Cr


16/36


P A G E 1 6

7.1.3 CO2Corrosion of Higher Alloy Steels

A protective layer also forms on the surfaces of higher alloy

steels in the formate brines where the higher buffer level has

been overwhelmed by a massive influx of CO2(Figure 9 for22Cr). The layers formed on these metals are of the thicker

variety (about 50100m). In spite of the slightly lower quality

of these films, the corrosion rates are very low due to the

resistance of these metals to both carbonic acid and formic

acid. No signs of pitting corrosion have been observed in any

of these materials exposed to buffered formate brines even

with a large amount of CO2influx.


on 22Cr in a potassium/cesium formate brine where pH was

pulled down to the lower buffer level by a large influx of CO2.

The thickness of the layer is about 50100 m.

7.1.4 CO2Corrosion Rates

General corrosion rates in formate brines as a function of

temperature and level of CO2influx are shown in Figure 10 to

Figure 14 for C-steel, 13Cr, modified13Cr (1Mo and 2Mo),22Cr, and 25Cr respectively. The data are taken from various

sources [6][7][8][9][10][11]. The data points represent

measurements done with and without H2Sin the headspace

and with and without chloride contamination in the formate

brine. Neither H2Snor chloride contamination appear to have

any significant impact on the CO2corrosion rates. For C-steel

and 13Cr steel, only the corrosion rates that were determined

by LPR or long term (30 days) weight loss tests have been

included. These are the true corrosion rates at which the

system will stabilize over time, and are not heavily inuenced

by the short-duration high corrosion rates that are measured

before the protective layer is formed. Rates that are known to

have been measured with unrealistic volume-to-surface

ratios are also excluded.

For Alloy 718 (not plotted), the measured corrosion rates are

negligible, in the order of 0.035 mm/y / 1.4 MPY after

overwhelming the buffer with CO2.

When using measured CO2corrosion rates for formate

brines, which have been measured after the buffer has been

overwhelmed; one would need to consider the timing aspect

of these rates.

Buffered FORMATE BRINES do not allow corrosion of downhole components unless and until the carbonate buffering

effects are overcome. This will normally take an extended period, or it might never happen during the life of

the well. When, due to CO2influx, the pH does drop to a point where corrosion can occur the formation of a

protective iron carbonate layer is promoted, particularly on carbon steels, and pitting of CRAs is not seen.

Influx of CO2into HALIDE BRINES causes an immediate (further) drop in pH and increased corrosion occurs. The

formation of a protective iron carbonate layer on carbon steels is hindered or prevented and the pitting of CRAs

promoted by the presence of halide ions.

Table 7 Average corrosion rate (weight loss) and corrosion rate for the deepest attack for 13Cr-steel in the two 1.53 s.g. / 12.8 ppg

bromide brines, the 1.53 s.g. / 12.8 ppg potassium formate brine, and the 1.70 s.g. / 14.2 ppg potassium/cesium formate brine.

Fluid Temp [C] days

Corrosion rate

Average rate At deepest attack

mm/y MPY mm/y MPY

CaBr2 120 1801) 62 0.061 2.4 2.1 83

CaBr2-inhibited 120 1801) 62 0.055 2.2 2.6 103

KFo 120 1801) 50 0.72 28.3 --- ---

KCsFo 150 34 0.249 9.8 --- ---

KCsFo 175 34 0.119 4.7 --- ---

1) These tests were run at 120C / 248F, with a quick ramp-up to 180C / 356F and down again after 1,000 hours in the bromides and 700 hours in theformates.

Corrosion

film

22Cr


17/36


P A G E 1 7

Figure 10 Measured general corrosion rates for C-steel in buffered formate brines with various levels of CO2influx and in some cases

H2S. Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an

intact buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of

these tests.

Figure 11 Measured general corrosion rates for 13Cr in buffered formate brines with various levels of CO2influx and in some cases H2S.

Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact

buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.


18/36


P A G E 1 8

Figure 12 Measured general corrosion rates for modified 13Cr (1Mo and 2Mo) in buffered formate brines with various levels of CO2influx and

in some cases H2S. Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3;

an intact buffer is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these

tests, apart from a couple of tests reported by Statoil and CSM [11] where the brine was contaminated with a very high level of chloride.


Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact buffer

is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.


Most rates are taken from long term LPR plots. Formate brines contaminated with chloride are also included. (See Figure 3; an intact buffer

is considered to correspond to a pH of about 9.5 and above.) No localized/pitting corrosion has been reported in any of these tests.


19/36


P A G E 1 9

7.2 Impact of CO2on SCC

Until quite recently, it was widely believed that SCC of CRAs in

completion and packer fluids was only likely to be a problem if

the fluid was contaminated with oxygen and contained some

chloride. Recently, new laboratory data emerged, suggesting

that some CRAs were also susceptible to SCC in bromide

brines containing no added chlorides [5]. This discovery was

soon followed by the revelation that SCC of CRAs could take

place in oxygen-free bromide brines contaminated with CO2[12].

SCC has never been experienced with formate brines in the

field. In the laboratory, SCC has never been experienced in

30-day tests in the presence of CO2. Only limited evidence of

SCC has been experienced in modified 13Cr steel at an

extended test period or with presence of H2S. Extensive SCC

testing has been carried out on formate brines by two research

groups: Hydro Corporate Research Centre in Norway [12] and

Centro Sviluppo Materiali SpA in Italy [10][11].

7.2.1 Testing by Hydro Corporate Research Centre

Hydro Research tested CRAs for SCC after exposure tobuffered 1.7 s.g. / 14.2 ppg potassium/cesium formate brine.

They used the U-bends and C-rings, pre-stressed to yield

method. A 1.7 s.g. / 14.2 ppg calcium bromide brine was

included in the testing for comparison. Both brine types were

contaminated with 1% Cl-. No oxygen scavengers or

corrosion inhibitors were added to either brine. The fluids

were tested at 160C / 320F over a period of three months

with visual inspection after each month. Testing was done

with 1 MPa / 145 psi CO2in the headspace, which immediately

overwhelmed the upper buffer level (the carbonate portion) of

the carbonate/bicarbonate buffer in the formate brine and

allowed pH to drop to the second buffer level. The CRAs that

were tested included triplicate specimens of modified 13Cr-1Mo,

Duplex 22Cr, and Super Duplex 25Cr.

The metal coupons were galvanically coupled to the loading

bolts (C-276) and stressed to beyond yield. All oxygen was

thoroughly removed by flushing at least 6 times with 1 MPa /

145 psi of test gas before testing and after each inspection.

All of the test metal samples were inspected with an optical

microscope after the first and second months. At the end of the

exposure period the crack patterns in the specimens that had

failed were studied in cross-section under an optical

microscope.

Table 8 shows the test results. At the end of the 3-month test

period none of the metal samples exposed to the formate

brine showed any signs of stress corrosion cracking. In the

bromide brine, both modified 13Cr-1Mo and Duplex 22Cr

showed signs of cracking after only 1 month, and Super

Duplex 25Cr showed evidence of cracks at the initiation

stage in the third month. This clearly demonstrates that under

the conditions used in this test program, oxygen is not

required for SCC to take place in bromide brines; the

presence of CO2is enough.

To our knowledge, there are no additives that can prevent the

SCC failures in the halide brines containing CO2. No additives

are currently available to scavenge CO2from divalent halide

brines, and if such an additive did exist, it would deplete over

time if the CO2influx was persistent. Also, commonly used

corrosion inhibitors are known to be ineffective in preventing

the onset of SCC.

The formate brine was tested under the most aggressive

conditions, i.e. the upper buffer level was overwhelmed

(depleted), representing the very worst case where CO2had

leaked into the brine over a very long period of time. The results

show that no additives or treatments other than buffering are

required in formate brines to prevent SCC from a CO2influx.

Table 8 Hydro Corporate Research Centre Long term SCC testing on a 1.7 s.g. / 14.2 ppg potassium/cesium formate brine and a

1.7 s.g. / 14.2 ppg calcium bromide brine, with CO2headspace. Temperature = 160C / 320F, and PCO2

= 1 MPa / 145 psi. The upper

buffer level in the formate brine was immediately overwhelmed and the pH was allowed to drop to the lower pH level. The tests were

run for three months with visual inspection of the specimens after each month.

Test specimenResults [SCC]

CaBr2+ 1% Cl- KCsFo+1% Cl-

1 month 1)

Modified 13Cr-1Mo LC80-130M 3/3 No

Duplex 22Cr EN 1.4462 3/3 No

Duplex 25Cr EN 1.4410 No No

2 months 1) 2)



Duplex 25Cr EN 1.4410 No No

3 months 2)




crack cracks at the initiation stage no cracking

1) For the first and second month the cracking evaluation is only based on visual inspections and optical microscopy.2) These tests are not true 2 and 3 months tests as the cell has been opened for inspection. They do however provide a valuable comparison of the

cracking susceptibility of the two brines.


20/36


P A G E 2 0

7.2.2 Testing by Statoil at Centro Sviluppo Materiali

Centro Sviluppo Materiali used the four point bent beam

(fpbb) test to evaluate the SCC susceptibility of modified

13Cr-2Mo steel (5 different grades of 110 ksi) and alloy 718

in buffered cesium formate brine saturated with chloride at

165C / 329F [10]. The test was run for 1 month with a CO2

headspace pressure of 4 MPa. The amount of acid gas

added to the autoclaves was sufficient to drop the brine pH

to 8.38.5, but did not totally overwhelm the buffer. This

study concluded that the susceptibility to SCC and localized

corrosion was negligible in both metals (Table 9). There was

no evidence of embrittlement in any of the test metals.

Table 9 Centro Sviluppo Materiali fpbb testing in a 1.94 s.g. /

16.2 ppg cesium/potassium formate brine contaminated with

65 g/L Cl- at 165C / 329F. PCO2

= 4 MPa / 580 psi.

The results are taken from [10].

Test specimen

Results

Pitting SCC

Modified13Cr-2Mo

SubmergedLiquid/vapor interface

No No

No No

Alloy 718SubmergedLiquid/vapor interface

No No

No No

Statoil and Centro Sviluppo Materiali have also reported

some more extensive testing of a cesium/potassium formate

brine saturated with chloride and exposed to CO2[11]. The

CO2partial pressure was also 4 MPa / 580 psi. The final pH

of the brine was not reported, and it is therefore uncertain if

the buffer was overwhelmed or not. In addition to the four

point beam testing, this program also included slow strain

rate tensile (SSRT) testing performed in air at ambient

temperature to look for evidence of hydrogen embrittlement.

The testing gave the following results:

Modified 13Cr-2Mo

No SCC failures were observed with modified 13Cr-2Mo in

cesium formate and fresh water solutions. However, cracks

at the initiation stage were observed on modified 13Cr-2Mo

after 2 months at 140C / 284F. The results are shown in

Table 10.

The fact that Centro Sviluppo Materiali observed cracks at

the initiation stage on modified 13Cr-2Mo after 2 months at

140C / 284F, and Hydro Research did not on modified

13Cr-1Mo after 3 months at 160C / 320F could be related

to the difference in the chloride levels of the two brines (four

times higher in Statoils brine) or it could be related to the

difference in the test methods (Hydro Research opened the

test cell for visual inspection after each month).

Alloy 718

No failures were observed with alloy 718, but significant loss

of ductility was experienced. This phenomenon is discussed

in Section 11.

Table 10 Centro Sviluppo Materiali SSRT testing and fpbb testing of modified 13Cr-2Mo in 1.95 s.g. cesium/potassium formate brine

saturated with Cl-and exposed to CO2. PCO2= 4 MPa / 580 psi [11].

TemperatureTest duration (months) RA [%] EL [%] Cracks (fpbb) testing

C F

No exposure (reference) 52 21 --

100 212 1 74 20 No

140 284 1 nd nd No

140 284 2 nd nd Cracks at the initiation stage

165 329 1 nd nd No

170 338 1 nd nd No



21/36


P A G E 2 1

8 Corrosion in Formate BrinesContaminated withH2S

Hydrogen sulfide, H2S, is highly aggressive towards metallic

materials. Depending upon the material, H2Scan cause

general corrosion, pitting corrosion, sulfide stress cracking

(SSC), stress corrosion cracking (SCC), hydrogen induced

cracking (HIC), stress oriented HIC (SOHIC), and hydrogen

embrittlement, and can promote corrosion fatigue. H2S

concentrations of only 50 ppmw dissolved in drilling and

completion fluids can cause highly stressed steel to fail in a

matter of minutes.

H2Scan enter the completion or packer fluid either with

reservoir gas influxes (along with CO2) or from decomposition

of sulfur-containing additives used as corrosion inhibitors in

halide brines (for example thiocyanates). A number of recent

failures of subsurface well equipment in halide brines have

been attributed to the H2Sformed from the thermal decom-

position of sulfur-based corrosion inhibitors [13][14].

H2Sis a very weak acid with pKa1of about 7, and when

introduced into an aqueous solution, the following equilibrium

will establish:

(15)

+

+

(16)

Therefore, in an alkaline aqueous solution, such as buffered

formate brines, the dissolved H2Sgas will largely exist as

bisulfide (HS-).

In non-oxygenated solutions, corrosivity is determined in part

by the pH. The lower the pH the greater the tendency for

corrosion. In addition, pH determines the stability/solubility of

corrosion scales.

Low general corrosion is expected in view of the high pH of

formate brines buffered with carbonate/bicarbonate, even in

the presence of high concentrations of hydrogen sulfide

(which will chiefly exist as HS-). At this pH, since little

corrosion that could lead to hydrogen uptake can occur,

SSC is unlikely.

By contrast, in high-density halide brines, the pH is low

(typically 26), and the H2Sgas will be solubilized directly as

H2S. Soluble H2Sin acidic brines can cause severe SSC.

As an additional benefit, the formate brines do not require

corrosion inhibitors of any kind, thus removing a potential

man-made source of hydrogen sulfide and atomic hydrogen.

There is a remote possibility that H2Scould flow into a formate

completion or packer fluid together with an influx of CO2large

enough to overwhelm the upper buffer level so that pH will drop

to 66.5. Hydro Corporate Research Centre, Porsgrunn and

Statoil (at Centro Sviluppo Materiali SpA) have investigated

the possible consequences of such a scenario (see 8.2.4).

8.1 Impact ofH2Son General and Pitting Corrosion

Both Statoil (Centro Sviluppo Materiali) [10][11] and Hydro

Research [15] have included H2Sin some of their corrosion

experiments with CO2in formate brines. Hydro Research

concluded that the presence of H2Shad very little impact on

the quality of the protective iron carbonate film that forms on

carbon and 13Cr steel surfaces in formate brines, even in the

case where pH is reduced to the lower buffer level by

exposure to a massive influx of CO2. Only when an extremely

high concentration of H2Swas applied or at very low CO2/

H2Sratios, was localized corrosion experienced. Testing with

PH2S= 2 kPa / 0.29 psi and PCO2/ PH2S= 500 on C-steel

(covering the acid gas content and composition of all

production wells in the Gulf of Mexico and the North Sea),

standard 13Cr, and modified 13Cr-1Mo showed no impact

from the presence of H2S. At PH2S= 100 kPa / 14.5 psi and

PCO2/ PH2S= 4, some localized corrosion was experienced.

Corrosion rate results with H2Sfrom both laboratories are

included in the plots in Figure 10 to Figure 14. The small

amount of pitting corrosion that was reported by Statoil [11]

in the presence of H2Scould be promoted by the rather highchloride contamination level in their test brine (saturated).

8.2 Impact ofH2Son SCC and SSC

The following provides an outline of the cracking of metallic

materials in contact with H2Sin the aqueous environments

found in oil and gas production systems. It is thought that the

behavior described also provides an indication of the likely

cracking behavior of such materials in completion brines

contaminated by H2Sinflux.

The service variables temperature, H2Spartial pressure,

chloride concentration, and pH, and the presence of sulfur in

the environment can, depending upon the material, affect its

cracking behavior. Produced sulfur is relatively rare in oil and

gas production environments. It can, however, also occur as

a result of the reaction of oxygen contamination, introduced

via surface facilities, with any H2Sthat is present.

The metallurgical state of an alloy and the total stress in a

material (the sum of both applied and residual stresses) are

also important variables in both these forms of cracking.

8.2.1 Sulfide Stress Cracking (SSC) of Carbon

and Low Alloy steels

SSC can affect susceptible carbon and low alloy steels at

very low H2Spartial pressures.

Figure 15 (taken from NACE MR1075/ISO 15156-2 [16])

defines the boundaries within which various strengths of

steels (often expressed in terms of hardness) remain crack

resistant when exposed to various H2Spartial pressures and

environmental pH values at room temperature. Materials

suitable for use in region 3 are also suitable for use in regions

0, 1 and 2 but not vice-versa.

As the temperature of the environment increases the

susceptibility of carbon and low alloy steels to SSC


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P A G E 2 2

decreases and above about 100C / 212F cracking is not

normally observed.

The other environmental variables listed above are much less

important with respect to SSC.

As can be seen, pH is an important factor in cracking

behavior of these steels and hence the pH of buffered

formate brines (normally > 6.5 even after significant influx of

acid gases) is expected to make this form of attack much less

likely than in other completion brines (halide brines) whose

pH falls quickly when affected by the influx of CO2/ H2S.

8.2.2 Cracking of CRAs inH2SContaining Environments

More detail on the limits of applicability of CRAs in oil and

gas production environments containing H2Sis given in the

industry standard NACE MR0175/ISO 15156-3 [2]. The

information below refers to a primary mechanism of cracking

for the alloys discussed. More details on possible cracking

mechanisms are given in Reference [2], Annex B, Table B.1.

Sulfide Stress Cracking of Martensitic Stainless Steels

Martensitic stainless steels, such as the standard 13Cr andmodified 13Cr alloys are also subject to SSC as a mechanism

of cracking failure in H2Scontaining media. The H2Spartial

pressure limit set by the industry for the more widely used

alloys is 10 kPa (1.5 psi) at a pH no lower than 3.5.

It is believed, given the involvement of hydrogen uptake in

SSC, that at a higher pH, and/or a higher temperature, a

higher level of H2Swould be acceptable and that it may be

possible to construct a diagram similar to that in Figure 15 for

these alloys.

The other environmental variables listed above appear less

important with respect to the SSC of martensitic stainless

steels.

The likely importance of pH suggests that the cracking

behavior of these alloys in relation to brines of different types

will be similar to that of carbon and low allow steels.

Stress Corrosion Cracking of other CRAs

The stress corrosion cracking of austenitic and duplex

stainless steels is dependent in a complex way upon

temperature, H2S partial pressure, and chloride concentration.

For nickel based alloys the role of chloride concentration

appears less important than the other variables. The role of

pH in the cracking of all these alloys is less clear. Many alloys

are made more susceptible to cracking by the presence of sulfur.

The relatively low level of chloride in buffered formate brines

when compared to halide brines would be expected to make

some of these alloys less susceptible to SCC in the presence

of H2S.

In the laboratory data, reported in 8.2.3 to 8.2.5 below, little

or no evidence for SCC has been seen in formate brines.

8.2.3 High-Temperature Testing by CAPCIS

CAPCIS tested CRAs for SCC after exposure to buffered

1.7 s.g. / 14.2 ppg potassium/cesium formate brine at high

temperature (160C / 320F) [18]. U-bends and C-rings,

pre-stressed to yield method was used in accordance with

previous test programs performed by Hydro Research (Section

7.2.1 and 9.1.1). A 1.7 s.g. / 14.2 ppg calcium bromide brine

was included in the testing for comparison. No oxygen

scavengers or corrosion inhibitors were added to either brine.

The fluids were tested at 160C / 320F over a period of

Figure 15 Regions of environmental severity with respect to SSC of carbon and low alloy steels at room temperature. The limits are

taken from NACE MR0175 / ISO 15156-2 [16].


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P A G E 2 3

1 month. Testing was done in Hastalloy vessels with

1 MPa / 145 psi CO2and 10kPa / 1.45 psi H2Sin the

headspace. The CRAs that were tested included triplicate

specimens of modified 13Cr-2Mo, Duplex 22Cr, Super

Duplex 25Cr, and alloy 718. The metal coupons were

galvanically coupled to the loading bolts (C-276) and

stressed beyond yield. In addition to the U-bend test pieces,

pre-machined, unloaded, tensile test pieces of each material

were added to assess the effect of any hydrogen uptake on

tensile properties. Coupons of each material were also

included for measurement of dissolved hydrogen. After the

specimens were added to the test vessel the vessel was

sealed and pressurized 5 times with 1 MPa CO2. The test

solutions were de-aerated by purging with nitrogen for at

least 12 hours prior to transfer to the test vessel. The test

solutions were purged with CO2in the test vessel for 30

minutes before introducing the test gas mixtures. At the end

of the exposure period the crack patterns in the specimens

that had failed were studied in cross-section under an optical

microscope.

During the test, the pH dropped from 11.9 to 7.60 (undiluted)

in the buffered formate brine, which indicated that the upper

buffer level of the carbonate/bicarbonate buffer was

overwhelmed. The pH in the bromide brine dropped slightly

from 3.41 to 3.30 (undiluted).

Table 11 shows the test results. At the end of the 4-week

test period only the modified 13Cr-2Mo test specimens

showed cracks at the initiation stage in the formate brine

(0.11 mm cracks on cross sections). In the bromide brine, all

modified 13Cr-2Mo samples and one of the alloy 718

samples were fractured. The tensile test pieces were tested

for changes in ductility within 6 hours after removal from the

test vessel to minimize loss of any absorbed hydrogen.

Samples were stored in liquid nitrogen after cleaning and

warmed up shortly before tensile testing. Coupons for

hydrogen measurement were brushed clean and analyzed

by vacuum hot extraction (VHE). Results of tensile tests and

hydrogen measurements are listed in Table 12. Some of the

samples that were exposed to the two brines, CO2and H2S,

contained probably slightly elevated levels of hydrogen. They

were not affected significantly by hydrogen embrittlement

apart from one anomalously high yield strength value fromAlloy 718 in CaBr2.

Table 12 CAPCIS room temperature tensile test data (EN10002-1) and hydrogen measurements after exposure to 1.7 s.g. / 14.2 ppg

calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines at 160C / 320F for 30 days. PCO2

= 1 MPa / 145 psi and

PH2S=10 kPa / 1.45 psi. The tensile data are the average of measurements done on two test specimens. The hydrogen levels are based

on one single test.

Test specimen

Yield stress (Rp0.2)% of initial value

Tensile strength %of initial value

Elongation % ofinitial value

Hydrogen uptake[ppm]

CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo

Modified 13Cr-2Mo 100 100 101 99 99 100 0.9 1.0

Duplex 22Cr 105 95 102 92 101 95 3.1 3.2

Duplex 25Cr 107 95 106 94 88 99 2.4 6.8

Alloy 718 112 1) 94 106 97 96 97 6.0 4.8

1) One sample showed 103% change; the other showed 121% change.

Table 11 CAPCIS testing of 1.7 s.g. / 14.2 ppg calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines exposed to

CO2(1 MPa / 145 psi) and H2S(10 kPa / 1.45 psi) at 160C / 320F for 30 days.

Test specimenResults [SCC]

CommentCaBr2 CsKFo

1 month

Modified 13Cr-2MoSM13CRS-110ksi /UNS S41426

3/3 3/3 CsKFo: Cracks on cross-

sections 0.11 mm

Duplex 22CrEN 1.4462 /UNS S31803

No No

Duplex 25CrEN 1.4410 /UNS S32760

No No

Alloy 718 UNS N07718 1/3 No



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P A G E 2 4

8.2.4 High-Temperature Testing by Statoil at

Centro Sviluppo Materiali

Statoil completed some four point bent beam (fpbb) testing

at Centro Sviluppo Materiali, in 1.95 s.g. buffered cesium

formate brine exposed to CO2and H2S[10]. In this testing,

the acid gas exposure was sufficient to overwhelm the upper

buffer level (the carbonate part) and drop the pH to the lower

buffer level. Table 13 shows the results from these tests anda test with only CO2. The addition of H2Sdid not cause any

cracking of the modified 13Cr-2Mo over the 1 month

exposure period. There was some evidence of embrittlement

of the modified 13Cr-2Mo and alloy 718 used in the tests

with H2S.

Statoil and Centro Sviluppo Materiali also included the same

amount of H2S(PH2S= 3 kPa / 0.44 psi) in their four point bent

beam and SSRT testing [11] reported in Table 10 in the

previous chapter (modified 13Cr-2Mo, given 1 month of

exposure to cesium formate brine at 170C / 338F in the

presence of 4 MPa CO2). This showed cracks at the initiation

stage and some absorption of hydrogen into the steel. Under

the same test conditions, in the absence of H2S, there was

no cracking and no absorption of hydrogen into the steel

during the 1 month exposure. The paper does not state if the

cracks were caused by SCC or if it was SSC occurring during

cooling of the test sample. For alloy 718, there were no

failures but loss of ductility with and without H2S. This is

discussed further in Section 11.

There are no results listed for similar tests in halide brines

with H2S. The paper does, however, state that the presence

of CO2and H2Screated severe SCC in modified 13Cr-2Mo

metal samples immersed inZnBr2/CaBr2/CaCl2and CaBr2/

CaCl2brines, and that transgranular cracks were also found

in one of the tests.

H2Sformed by the thermal decomposition of sulfur-

containing corrosion inhibitors is another well-known cause

of SSC and SCC in completion/packer fluids. Corrosion

inhibitors are not required in formate brines, and so one

troublesome source of corrosion is eliminated.

8.2.5 Low-Temperature Testing by CAPCIS

CAPCIS tested CRAs for SSC after exposure to buffered

1.7 s.g. / 14.2 ppg potassium/cesium formate brine at low

temperature (40C / 104F) [18]. U-bends and C-rings, pre-

stressed to yield method, were used. A 1.7 s.g. / 14.2 ppg

calcium bromide brine was included in the testing for

comparison. No oxygen scavengers or corrosion inhibitors

were added to either brine. The fluids were tested at 40C /

104F over a period of 1 month. Testing was done in

Hastalloy vessels with 1 MPa / 145 psi CO2and 10kPa / 1.45

psi H2Sin the headspace. The CRAs that were tested

included triplicate specimens of modified 13Cr-2Mo, Duplex22Cr, Super Duplex 25Cr, and alloy 718. The metal coupons

were galvanically coupled to the loading bolts (C-276) and

stressed beyond yield. In addition to the U-bend test pieces,

pre-machined, unloaded, tensile test pieces of each material

were added to assess the effect of any hydrogen uptake on

tensile properties. Coupons of each material were also

included for measurement of dissolved hydrogen. After the

specimens were added to the test vessel the vessel was

sealed and pressurized 5 times with 1 MPa CO2. The test

solutions were de-aerated by purging with nitrogen for at

least 12 hours prior to transfer to the test vessel. The test

solutions were purged with CO2in the test vessel for 30

minutes before introducing the test gas mixtures. At the end

of the exposure period the crack patterns in the specimens

that had failed were studied in cross-section under an optical

microscope.

During the test, the pH dropped from 11.9 to 7.63 (undiluted)

in the buffered formate brine, which indicated that the upper

buffer level of the carbonate/bicarbonate buffer was

overwhelmed. The pH in the bromide brine increased slightly

from 3.41 to 3.65 (undiluted).

Table 14 shows the test results. At the end of the 4-week

test period no sign of cracking was seen on any of the test

specimens in the formate brine. In the bromide brine, all

modified 13Cr-2Mo samples showed signs of cracks at theinitiation stage. The tensile test pieces were tested for

changes in ductility within 6 hours after removal from the test

vessel to minimize loss of any absorbed hydrogen. Samples

were stored in liquid nitrogen after cleaning and warmed up

shortly before tensile testing. Coupons for hydrogen

measurement were brushed clean and analyzed by vacuum

hot extraction (VHE). Results of tensile tests and hydrogen

measurements are listed in Table 15. Some of the samples

that were exposed to the two brines, CO2, and H2Scontained

probably slightly elevated levels of hydrogen, but were not

affected significantly by hydrogen embrittlement.

Table 13 Centro Sviluppo Materiali fpbb testing of modified 13Cr-2Mo and alloy 718 in a 1.94 s.g. / 16.2 ppg CsKFobrine at 165C / 329F.

PCO2= 4 MPa / 580 psi. The results are taken from [10].

FluidH2S

Position in test cellModified 13Cr-2Mo Alloy 718

[kPa] [psi] Pitting SCC Pitting SCC

1 Month

CsKFo+ 20 g/L Cl- 3 0.44 SubmersedLiquid/vapor interface NoNo NoNo NoNo NoNo

CsKFo+ 65 g/L Cl-Submersed

Liquid/vapor interfaceNoNo

NoNo

NoNo

NoNo

CsKFo+ 75 g/L Cl- 3 0.44Submersed

Liquid/vapor interfaceNoNo

NoNo

NoNo

NoNo


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P A G E 2 5

8.3 Use ofH2SScavengers in Formate Brines

The carbonate/bicarbonate buffer that is normally added to

formate brines when they are used as well construction fluids

provides useful protection against corrosion by H2S. The

alkaline pH helps to push the chemical equilibrium (Equation

16) towards the formation of bisulfide (HS-) from H2S(aq).

The capacity of the carbonate/bicarbonate buffer is enormous

(as demonstrated in Figure 3), and large amounts of acid gas

can be converted to HCO3-and HS-before the pH starts

dropping. The likelihood that a buffered formate brine would

ever receive a CO2gas influx large enough to overwhelm the

buffer during field use is low, but as can be seen from the

previous section (8.2.4), this could result in some loss of

ductility in CRAs and the addition of an H2Sscavenger could

be beneficial since the impact of H2Son lowering pH would

be reduced and less bisulfide ion, that might stimulate

hydrogen uptake, would be dissolved in the formate brine.

The addition of H2S scavengers has additional benefits over

the use of the buffer alone as the scavengers tie up the

sulfide rather than changing the equilibrium. Additionally, the

use of an additional H2Sscavenger will help to remove any

bisulfide from the formate brine.

A zinc-free, iron based H2Sscavenger, Ironite Sponge, has

been tested in formate brines, and is shown to have some

positive effect in scavenging the H2S. But Ironite Spongeis

a solid, which limits its application in clear completion fluids.

Another iron based scavenger, compatible with high

concentration formate brines, is iron gluconate [19], a Fe(II)

complex, which is water-soluble at high pH. In addition to

being solids free, this scavenger has the added benefit of

reacting very rapidly on a quantitative basis with sulfide.

8.5 kg/m3/ 3 lb/bbl of iron gluconate has been tested in a

buffered 2.2 s.g. / 18.3 ppg cesium formate brine (pH=11).

The added scavenger was shown to be compatible with the

brine; it dissolved completely within 5 minutes without any

change in pH.

A third iron based scavenger that may be compatible with

formate brines is iron oxalate. Compatibility testing still needs

to be carried out with this scavenger.

Another group of zinc-free H2Sscavengers that is expected

to be compatible with formates are the electrophilic organicinhibitors that bind up sulfur in an organic form. These have

the advantage that they do not form any solids when reacting

with H2S. These will also require compatibility testing.

Table 14 CAPCIS testing of 1.7 s.g. / 14.2 ppg calcium bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines exposed to

CO2(1 MPa / 145 psi) and H2S(10 kPa / 1.45 psi) at 40C / 104F for 30 days.

Test specimenResults [SCC] Comment

CaBr2 CsKFo

1 month

Modified 13Cr-2Mo SM 13CRS-110ksi /UNS S41426 3/3 No CaBr

2: cracks on cross sections 1.8 mmDuplex 22Cr EN 1.4462 / UNS S31803 No No

Duplex 25Cr EN 1.4410 / UNS S32760 No No

Alloy 718 UNS N07718 No No


Table 15 Room temperature tensile test data (EN10002-1) and hydrogen measurements after exposure to 1.7 s.g. / 14.2 ppg calcium

bromide and 1.7 s.g. / 14.2 ppg potassium/cesium formate brines at 40C / 104F for 30 days. PCO2= 1 MPa / 145 psi and

PH2S=10 kPa / 1.45 psi. The tensile data are the average of measurements on two test specimens. The hydrogen levels are based

on one single test.

Test specimenYield stress (Rp0.2)% of initial value Tensile strength% of initial value Elongation% of initial value Hydrogen uptake[ppm]

CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo CaBr2 KCsFo

Modified 13Cr-2Mo 100 102 101 99 93 98 1.3 1.0

Duplex 22Cr 104 109 101 104 93 92 1.2 1.7

Duplex 25Cr 102 104 103 105 96 92 1.3 1.4

Alloy 718 104 107 106 108 96 103 3.0 2.7


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P A G E 2 6

9 Corrosion in Formate BrinesContaminated with O2

Oxygen is generally accepted as a cause of general

corrosion, where the oxygen serves as an oxidant for

corrosion reactions. Concentrated formate brines have

beneficial properties that should help protect metals against

corrosion damage caused by oxygen:

1. Low solubility of oxygen in formate brines.

The solubility of oxygen in low-salinity aqueous solutions at

surface temperature and pressure is about 9 ppm. The

solubility decreases in high salinity formate brines, as shown

in Figure 16, and at elevated temperatures [20].

2. Formate brines are antioxidants.

Formate is a strong reductant, anti-oxidant, and free radical

scavenger. As this is a property of the formate ion itself,

which is present in massive quantities in high-density formate

brines, it will never be depleted.

Halide brines have no anti-oxidant properties. Therefore, if

oxygen is not removed from halide based drilling and

completion fluids, the soluble oxygen can cause severalforms of corrosion in sub-surface well equipment and

tubulars. For this reason, it is essential to add an oxygen

scavenger to halide brines. These scavengers are generally

quite effective until they become depleted (consumed) or

degraded, at which point further contamination with oxygen

could cause a problem. However, the standard bisulfite-

based oxygen scavengers are not particularly soluble in

calcium brines because they form solid calcium bisulfite. A

recent well tubular failure [21] was caused by oxygen (air)

ingress into a CaCl2packer fluid during an annular pressure

bleed-off operation. In this instance, the oxygen scavenger

present in the brine was apparently not able to cope with the

new influx of oxygen.

Concentrated formate brines contaminated with oxygen and

without added oxygen scavenger have never caused pitting

or SCC in the field. Laboratory testing with these brines

confirm their superior performance over halide brines.

brine compatibility with metal

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